Technical Report

NREL/TP-6A20-61350

May 2014

Contract No. DE-AC36-08GO28308

Overview of 

Variable 

Renewable Energy 

Regulatory Issues

A CLEAN ENERGY REGULATORS INITIATIVE REPORT

Mackay Miller and Sadie Cox 

National Renewable Energy Laboratory
Technical Report

NREL/TP-6A20-61350

May 2014

Contract No. DE-AC36-08GO28308

Overview of Variable 

Renewable Energy 

Regulatory Issues 

Mackay Miller and Sadie Cox 

National Renewable Energy Laboratory

Produced under the guidance of the Department of Energy and the Clean Energy Ministerial by the National 

Renewable Energy Laboratory under Interagency Agreement S-OES-12-IA-0010 and Task Number 

WW3N.1000.

NREL is a national laboratory of the U.S. Department of Energy, Office of Energy Efficiency & Renewable Energy, 

operated by the Alliance for Sustainable Energy, LLC.
NOTICE 

This manuscript has been authored by employees of the Alliance for Sustainable Energy, LLC (“Alliance”) under Contract No. DEAC36-08GO28308 with the U.S. Department of Energy (“DOE”).

This report was prepared as an account of work sponsored by an agency of the United States government. Neither the United 

States government nor any agency thereof, nor any of their employees, makes any warranty, express or implied, or assumes any 

legal liability or responsibility for the accuracy, completeness, or usefulness of any information, apparatus, product, or process 

disclosed, or represents that its use would not infringe privately owned rights. Reference herein to any specific commercial 

product, process, or service by trade name, trademark, manufacturer, or otherwise does not necessarily constitute or imply its 

endorsement, recommendation, or favoring by the United States government or any agency thereof. The views and opinions of 

authors expressed herein do not necessarily state or reflect those of the United States government or any agency thereof. 

Printed on paper containing at least 50% wastepaper, including 10% post consumer waste. 
iii

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Acknowledgments

The authors wish to thank the expert staff of the Regulatory Assistance Project, Leonardo Energy, and the 

International Copper Association for their insights and research on the topic of clean energy regulation. 

The authors would also like to acknowledge Jaquelin Cochran, Aaron Bloom, Jeffrey Logan, and Doug 

Arent for their contributions to this report. Finally, the authors are greatly indebted to Scott Gossett and

Kendra Palmer in NREL Communications for their production support. 
iv

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Executive Summary

This report focuses on key regulatory issues associated with the deployment of variable renewable energy 

(VRE) sources, especially wind and solar power. Drawing upon research and experiences from various 

international contexts, the report identifies key issues and ideas that have emerged as VRE deployment 

has grown and presents a framework for understanding regulatory issues within the larger context of 

power system evolution. Finally, in order to help regulators anticipate issues that may arise in the future, 

the report aims to provide a forward look at regulatory lessons learned in cases of high penetrations of 

VRE. 

Based on international experience, there is not a one-size-fits-all approach to the regulation of VRE. 

Many variables shape the issues that arise in a given context, especially power system characteristics, 

geographic and spatial availability of VRE resources, institutional organization of the power system, 

public policy goals, and the political economy of power system issues. Despite these variations, common 

issues arise at each stage of VRE deployment. This report identifies four broad categories of issues, and 

the structure of this report follows this categorization: 

• Facilitating New VRE Generation

In accordance with policy mandates, regulators play a role in facilitating new VRE generation 

through various mechanisms, including setting tariffs, organizing auctions, and influencing grid codes 

and the interconnection of new VRE generation.

• Ensuring Adequate Grid Infrastructure

Regulators play a role in shaping the grid infrastructure 

development of a power system, which is a key dimension 

of VRE deployment and system integration. 

• Ensuring Short-term Security of Supply (Flexibility) 

Regulators play a role in encouraging power system 

flexibility, which in turn plays an important role in the 

integration of VRE into power systems, especially as levels 

of deployment grow.

• Ensuring Long-term Security of Supply (Resource

Adequacy) 

Regulators play a key role in ensuring adequate power 

system resources, including incorporating VRE into resource 

planning, and managing potential impacts on the economics of other resources in the system. 

These four domains are interrelated, and become more so as VRE deployment levels grow. The report 

surveys regulatory experiences around the world in each of these domains, providing brief ‘snapshots’ of 

emerging challenges and solutions from countries including Australia, Denmark, Germany, Guatemala,

India, Mexico, the United Kingdom, and the United States. From these varied experiences, the report 

identifies key regulatory ideas in each of the four domains: 

Facilitating New VRE Generation

• Linking RE tariffs to delivered and metered power incentivizes efficient system siting and operation.

• Tariffs can be designed to promote investment and achieve policy goals while limiting total costs to 

the public.

• Simplifying interconnection procedures for distributed resources is often complementary to other 

procurement measures such as policy targets and specialized tariffs.

VRE 

Generation

Grid 

Infrastructure

Resource 

Adequacy Flexibility

Figure ES-1. The four main 

categories of VRE regulation
v 

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• Replacing ‘first-come, first-served’ interconnection processes with a more orderly and transparent 

process based on system impacts can result in more efficient outcomes and provide more clarity to 

investors.

• Harmonizing interconnection procedures with robust technical standards can encourage investment 

while maintaining reliability.

Ensuring Adequate Grid Infrastructure 

• In cases where there is plausible risk of stranded transmission assets, one common risk management 

approach is to place the risk on parties best able to evaluate and manage it. 

• Network usage charges can significantly alter VRE project economics and can be designed to 

advance policy goals.

• Transmission expansion costs can be minimized through coordinated planning processes that identify

high-quality resource areas, address investment risk through funding structures that ensure cost 

recovery, and engage stakeholders throughout the process.

• Distribution grid concerns at high VRE penetrations can be mitigated through advanced grid codes 

and allowance for strategic curtailment of VRE.

Ensuring Short-term Security of Supply (Flexibility) 

• Changes to system operational and forecasting methods can be combined to unlock physical 

flexibility and enhance system reliability under growing shares of VRE.

• Reserve requirements can be reduced through advanced forecasting techniques and effective 

integration of those techniques into power system operation.

• Compared to low-VRE scenarios, preliminary analysis indicates that high VRE penetrations require 

additional reserve requirements, though these are relatively small compared to total system size, and 

important differences in reserve impacts emerge depending on the mix of solar and wind generation.

• Demand Response represents an important source of flexibility, and large-scale DR participation will 

depend upon regulatory clarification of eligibility, performance characteristics, performance 

validation, and compensation mechanisms. 

Ensuring Long-term Security of Supply (Resource Adequacy) 

• Resource adequacy issues raise multiple issues related to investment incentives and business model 

evolution for conventional thermal generators, and of risk allocation between generators and load.

• VRE procurement at high penetrations can be sustained through increased support for resource 

characterization and project site assessment, and through streamlined, transparent processes.

• Institutional measures to expand balancing areas can result in greater flexibility due to lower 

aggregate variability and higher aggregate reserve capacity, lessening concerns over resource

adequacy.

While there are unique forces at play in each regulatory context, the report provides a framework that 

highlights the common issues and key ideas that emerge across contexts and at each stage of VRE 

deployment and integration. In support of increased international collaboration through the Clean Energy 

Regulators Initiative, the report concludes with an exploration of priority areas of focus for regulatory 

attention and innovation. 
vi 

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Table of Contents

1 Introduction: A Brief Note on the Physical Characteristics of Variable Renewable Energy ........ 1

1.1 A Framework for Categorizing VRE Regulatory Issues.................................................................. 1

2 Early Stage Regulatory Issues............................................................................................................ 5

2.1 VRE Generation Procurement: Early Stage Issues.......................................................................... 5

2.1.1 Specialized Tariffs.................................................................................................................. 5

2.1.2 Auctions.............................................................................................................................. 6

2.1.3 Quotas and Targets ............................................................................................................. 7

2.1.4 Interconnection Queue Management .................................................................................. 7

2.2 Grid Infrastructure: Early Stage Issues............................................................................................ 8

2.2.1 Transmission Network Expansion ...................................................................................... 8

2.2.2 Network Usage Costs........................................................................................................ 10

2.2.3 Distributed Generation Network Interconnection............................................................. 10

2.3 Flexibility and Resource Adequacy: Planning for the Future........................................................ 12

3 Intermediate Stage Regulatory Issues ............................................................................................. 13

3.1 VRE Procurement: Intermediate Stage Issues............................................................................... 13

3.2 Grid Infrastructure: Intermediate Stage Issues............................................................................... 13

3.2.1 Transmission Network Expansion .................................................................................... 13

3.2.2 Distribution Network Development.................................................................................. 15

3.3 Flexibility: Intermediate Stage Issues............................................................................................ 19

3.3.1 Estimating Reserve Impacts of VRE ................................................................................ 19

3.3.2 Forecasting........................................................................................................................ 20

3.3.3 Improving System Operation Practices ............................................................................ 20

3.4 Resource Adequacy: Intermediate Stage Issues............................................................................. 22

3.4.1 Adequacy Mechanisms..................................................................................................... 23

4 Advanced Stage Regulatory Issues ................................................................................................. 27

4.1 Advanced Stage VRE Procurement Issues .................................................................................... 27

4.1.1 Evolution of RE Siting...................................................................................................... 27

4.2 Grid Infrastructure: Advanced Stage Issues................................................................................... 28

4.3 Advanced Stage Flexibility............................................................................................................ 28

4.3.1 High-penetration Reserve Requirements.......................................................................... 28

4.3.2 Evolution of Demand Response........................................................................................ 29

4.4 Resource Adequacy: Advanced Stage Issues................................................................................. 31

4.4.1 Institutional Coordination ................................................................................................. 31

5 Conclusion: Regulation for Comprehensive VRE Integration....................................................... 32

References................................................................................................................................................. 33
vii 

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List of Figures

Figure ES-1. The four main categories of VRE regulation ................................................................. iv

Figure 1. The four main categories of VRE regulation ......................................................................... 2

Figure 2. Illustration of FIT CfD strike price ........................................................................................ 6

Figure 3. Classification of transmission network cost allocation policies............................................. 9

Figure 4. "Competitive RE zones" and related transmission lines in Texas........................................14

Figure 5. Investment properties of transmission and distribution networks........................................15

Figure 6. Power flows between transmission and distribution network in the Puglia region of Italy, 

2010–2012 ....................................................................................................................................16

Figure 7. February 2014 "Locational Value Map" of Oahu, illustrating PV penetration as a percent of 

daytime minimum load .................................................................................................................17

Figure 8. Wind energy as a percentage of energy consumption, Tamil Nadu, India, 2010–2013.......26

Figure 9. Five-minute changes in power density: load only, high wind, and high solar scenarios.....29

List of Tables

Table 1. Illustrative Issues and Actions Associated with Different Stages of VRE Deployment ......... 3

Table 2. Administrative and Market-based Constructs for Adequacy ................................................23

Table 3. Resource Adequacy Mechanism Options Examined for the ERCOT System ......................24

Table 4. Simulated Reserve Requirements of Different Wind/Solar Mixes in the WWSIS Phase 2 

Analysis (NREL 2013) .................................................................................................................29

Table 5. Necessary Attributes for DR to Supply Ancillary Services in the CAISO Market...............30
1 

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1 Introduction: A Brief Note on the Physical Characteristics of 

Variable Renewable Energy

Just as the unique physical characteristics of electricity networks strongly influence regulation of the 

electricity sector,

1 the unique physical characteristics of variable renewable energy (VRE) strongly shape 

associated regulatory issues. A more thorough examination of the relevant physical characteristics of 

specific VRE technologies will be provided later in the CERI report series. For the purposes of this report, 

the relevant characteristics of VRE that impact regulation are: 

• Resource geography. Wind and solar power resources vary significantly by geography; some places 

are sunnier or windier than others. From a regulatory perspective, geographically-constrained

resources can translate into the need for modified procedures, such as tailored cost-benefit assessment

of transmission network expansion to deliver remote VRE power onto the grid.

• Variability. Wind and solar power resources vary over time. While variability is a natural feature of 

power systems, the additional variability of VRE often merits regulatory attention—for instance in 

defining the level of capacity credit for each incremental megawatt (MW) of VRE, and in 

determining the level of conventional generation capacity to be held in reserve to reliably balance 

VRE fluctuations.

• Uncertainty. The precise availability of wind power (and to a lesser extent, solar power) during any 

given hour of the year is inherently uncertain. The level of uncertainty of VRE power production is 

reflected in wind and solar forecasting errors. Although uncertainty is a natural feature of power 

systems, the uncertainty of VRE can impact regulatory needs, such as the setting of rules for 

forecasting and power system operation. 

• Electrical interactions. VRE has distinct electrical characteristics that interact with alternating current 

(AC) electricity grids differently than conventional rotating generators. For example, conventional 

rotating generators produce torque and spin synchronously with the load-frequency of the system. As 

such, each generator provides inertia to the system. In contrast, the majority of wind turbines—and all 

PV systems—are asynchronous, meaning that they are not directly coupled with the system frequency

except through power electronics. These electrical characteristics can merit regulatory attention in the 

establishment of interconnection protocols and grid codes. 

While these unique technical characteristics are important for regulators to understand, it is equally 

important to understand that their aggregate impact varies widely and is a function of the unique 

interactions between the VRE generation profile and the specific power system as well as the market and 

regulatory context. A 15% penetration of VRE power (measured as a percentage of annual generation)

may be easily integrated in one power system while causing significant challenges in another, depending 

upon a range of factors including resource distribution, market rules, system size, grid reliability, level of 

interconnection, and system operation protocols. 

1.1 A Framework for Categorizing VRE Regulatory Issues

Given the diversity of power systems globally, and the interdependency between regulatory options and 

system context, establishing universally applicable rules for regulation of VRE is not feasible. 

Nonetheless, experience can shed light on common high-level issues and concerns that arise from early to 

advanced stages of VRE. These regulatory issues fall into four broad and interrelated categories,2 which 

are illustrated in Figure 1 and constitute the recurring themes of this report: 

 

1 An introduction to the interaction of electricity with network regulation can be found in Pérez-Arriaga (2013). 2 These four categories are adapted from Miller et al. (2013). That report explores associated technical and policy considerations 

in more detail.
2 

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• Facilitating New VRE Generation

While the impetus for new VRE generation is typically driven 

by policy or economic factors, regulators play a crucial role in, 

inter alia, setting tariffs, facilitating auctions, shaping grid 

codes, and influencing the interconnection of new VRE

generation. These regulatory functions can strongly influence 

the pace of new VRE deployment.

• Ensuring Adequate Grid Infrastructure

Grid infrastructure enables VRE deployment, and regulators 

play a crucial role in shaping the grid investment landscape, 

especially with regard to planning, siting, cost allocation, and 

cost recovery. 

• Ensuring Short-term Security of Supply (Flexibility) 

Significant penetration of VRE brings increased variability and uncertainty to power system 

operations. Regulators play a crucial role in employing strategies that ensure system flexibility in a 

cost-efficient manner, such as encouraging the integration of forecasting into system operations and 

encouraging investment in flexible demand- and supply-side resources. 

• Ensuring Long-term Security of Supply (Resource Adequacy) 

The impact of VRE on resource adequacy is important in all settings, though the regulatory role 

varies considerably depending upon the level of excess generation capacity in the existing power 

system. In systems with excess capacity, VRE generation can erode the volume of conventional 

generation and suppress average market prices for energy, placing financial stress on legacy 

conventional generators, which leads to concerns over sufficient conventional dispatchable capacity. 

In systems with capacity scarcity, the contribution of VRE generation instead tends to mitigate overall 

capacity shortages and the contribution depends significantly upon the resource profile and the ability 

of the system to accommodate all of the resulting generation (in other words, to minimize curtailment 

of the resource). These two broad contexts (alternately termed “stable” and “dynamic” contexts in 

Müller [2013]) correspond roughly to Organization for Economic Cooperation and Development

(OECD) and non-OECD countries, respectively.

These four categories represent the key domains of VRE regulation. Also important are the interactions 

between these domains—for example, the interdependency between VRE generation and grid 

infrastructure planning. Actions to address issues in these four domains are not static—they evolve as 

VRE deployment grows as a percentage of annual generation. Table 1 illustrates some potential 

regulatory actions that may be appropriate in each of these categories at early, intermediate, and 

advanced stages3 of VRE deployment. More darkly shaded squares indicate relatively greater importance 

at each stage.

 

3 For this report, the early stage equates to approximately 5% or less of VRE as a percentage of total annual generation, the 

intermediate stage equates to roughly 5-20% of annual generation, and the advanced stage equates to 20% or greater of annual 

generation, although the boundaries of these stages are not precise and depend heavily upon, inter alia, system characteristics and 

pace of deployment.

VRE 

Generation

Grid 

Infrastructure

Resource 

Adequacy Flexibility

Figure 1. The four main 

categories of VRE regulation
3 

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Table 1. Illustrative Issues and Actions Associated with Different Stages of VRE Deployment

VRE Generation Grid Infrastructure Short-term Security of 

Supply: Flexibility

Long-term Security 

of Supply: 

Adequacy

Early Stage

(VRE

approximately

< 5%4

)

Establish appropriate

VRE support 

mechanisms

Establish queue 

management

Establish efficient 

siting processes

Simplify

interconnection 

protocols

Initiate data collection 

efforts that will facilitate 

formal grid integration 

studies

Initiate data collection 

efforts that will 

facilitate formal grid 

integration studies

Intermediate 

Stage 

(VRE

approximately 

5-20%)

Refine VRE support 

mechanisms if 

necessary

Refine siting and 

queue management

Establish VRE grid 

codes and designated 

transmission zones

Coordinate generation 

and grid planning

Establish distribution 

network standards for 

VRE

Initiate formal grid 

integration study

Improve forecasting

Broaden balancingarea footprints

Improve system 

operation methods

Initiate formal grid 

integration study, with

capacity credit or 

resource adequacy 

components as 

needed

Advanced 

Stage 

(VRE

approximately 

>20%) 

Encourage alignment 

between demand and

VRE production

Incentivize VRE

dispatchability

Expand grid 

interconnection and 

market coupling

Employ locational 

pricing

Incentivize active 

network management

Employ advanced 

system operation 

Incentivize demand 

response (DR)

Incentivize flexible 

generation and/or 

storage

Improve adequacy 

mechanism in 

accordance with 

predominant 

paradigm 

(e.g., capabilities 

market; strategic 

reserve requirement; 

full scarcity pricing)

Table 1 reinforces how regulatory priorities evolve—and issues become more interdependent—as shares 

of VRE increase. For example: 

• In early stages (normally less than 5% of annual generation) regulatory concerns typically center on 

the establishment of mechanisms for procuring new RE generation and defining interconnection 

standards. Complex system integration issues are of a lower priority at these stages.

• In intermediate stages (typically between 5-20% VRE penetration) regulatory concerns increasingly 

center on the interactions between VRE and existing systems, such as how to achieve cost-efficient 

planning for grid expansion, how to identify VRE integration needs and evaluate costs, and how to 

allocate various charges to specific actors. 

• In advanced stages (as VRE generation surpasses 20% of annual generation) regulatory concerns 

increasingly focus on the evolution of the entire power system, such as significant changes to 

institutional arrangements, grid infrastructure, conventional generation assets, demand elasticity, and 

interactions with neighboring systems, which can complicate regulatory initiatives. 

 

4 The percentages provided here are illustrative. Actual stages of VRE impacts on a power system are highly context-specific.
4 

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KEY IDEA 

Regulatory issues of VRE are narrowly focused at early stages (mainly focused on VRE generation and 

grid infrastructure)

5 and expand to a more comprehensive scope at advanced stages (spanning all four 

framework areas). 

Following this framework, the remainder of the report is structured as follows. Section 2 briefly discusses 

early stage VRE regulatory issues, focusing primarily on generation procurement and grid planning. 

Section 3 discusses intermediate stage issues, focusing primarily on grid, flexibility, and adequacy

considerations. Section 4 briefly discusses emerging issues at advanced stages of VRE deployment, 

focusing primarily on grid. Section 5 concludes and summarizes key areas of focus for further research. 

 

5 However, rapidly growing and dynamic systems may be strongly focused on adequacy, even at early stages. 
5 

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2 Early Stage Regulatory Issues

In 2014, the majority of electric power systems around the world still procure less than 5% of annual 

generation from VRE sources. As such, the issues outlined in this section are of broad interest to many 

regulators, and benefit from the greatest body of accumulated knowledge and research. 

2.1 VRE Generation Procurement: Early Stage Issues

In 2014, energy from renewable sources is typically more expensive than energy from conventional 

sources,6

 so policy and regulatory interventions have emerged to promote deployment such as elevated 

tariffs, long-term contracts, or mandatory targets. Intervening in prices paid for energy is an important but 

complex role for regulators. This section will discuss key regulatory considerations involved in some of 

these mechanisms, reviewing lessons learned in their application. 

2.1.1 Specialized Tariffs 

Specialized tariffs are a common mechanism to spur RE deployment. Since the regulatory aspects of tariff 

setting in this regard are well known in the literature, this report will not discuss these concerns in detail.

The most common tariff instruments around the world are feed-in tariffs, or “FITs,” which set specialized

prices for various types of RE generation. Discussion of tariff setting for VRE can be found in Miller et 

al. (2013), Couture et al. (2010), Couture and Gagnon (2010), Klein et al. (2007). By guaranteeing a price 

linked to generation, FITs avoid some pitfalls associated with mechanisms linked only to investment 

costs, which may incentivize project developers to seek excess rents through arbitrage of the margin 

between the investment price and the price paid through the mechanism. Additionally, linking the 

premium to delivered power incentivizes developers to seek high-quality resource areas and to maintain 

facility output. The production tax credit employed in the United States shares these same characteristics.

KEY IDEA

Linking RE tariffs to delivered and metered power incentivizes efficient system siting and operation. 

2.1.1.1 “Future Proofing” Tariff and Procurement Mechanisms

VRE procurement mechanisms have long-lived terms, typically 10 years or greater, and it is important to

consider how to “future proof” these mechanisms against events such as technology cost reductions that 

can result in large mismatches between the tariff and the actual technology cost. In other words, early

stage design of tariffs can anticipate issues that may arise as VRE technology costs decline and overall 

penetrations increase. Recent history has revealed the importance of ensuring that procurement 

mechanisms appropriately limit public risk and cost as VRE deployment grows. For example, FITs can 

aim to incorporate more accurate information about current and projected technology costs in order to 

limit windfall profits if technology costs fall precipitously. Over the period of 2008-2013, the public costs 

of solar PV tariffs in Spain and Germany have risen and have become the subject of political debate 

(Economist 2010; Economist 2011; Economist 2012). The case of the United Kingdom provides one 

perspective on emerging mechanisms to limit public cost exposure.

2.1.1.1.1 Snapshot: United Kingdom FITs with “Contracts for Difference”

Challenge: The UK government is faced with setting tariffs that meet the dual challenges of meeting 

ambitious RE and greenhouse gas (GHG) emission mitigation targets while also ensuring low cost 

electricity. 

 

6 The relative cost of renewable and conventional energy is heavily dependent upon inter alia accounting approaches, externality 

costs, and system characteristics. In some areas (such as remote islands) VRE is already less expensive than most or all other 

imported energy sources.
6 

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Solution: To address these challenges, the UK government, through its Department of Energy and

Climate Change and its independent Office of Gas and Electricity Markets (Ofgem), and with input from 

various stakeholders, proposed and adopted a mechanism called “Feed-in Tariffs with Contracts for 

Difference” (FIT CfD) under the country’s broader Electricity Market Reform (EMR). At the center of 

the FIT CfD design are the ‘strike prices’ for four different technology types (onshore wind, offshore 

wind, biomass, and ‘other’); these are set for five-year periods. The FIT CfD stabilizes revenues within a 

pre-determined range, set by the strike price, for the duration of the contract. When the market price for a 

generator’s electricity is less than the strike price (see Figure 2), the generator receives the difference in 

payment. When the market price is more than the strike price, the generator pays back the difference (in 

other CfD designs, the generator simply receives no payment). Relative to spot prices, FIT CfDs reduce 

revenue uncertainty for VRE power. Relative to conventional FITs, FIT CfDs bound the risk to the 

customer and reduce incentives to bid VRE electricity into markets even when market prices are negative, 

thus increasing efficient market performance. Technical details of the UK FIT CfD scheme can be found 

in DECC (2012). A more extensive examination of the challenges of FIT CfD implementation can be 

found in RAP (2013). 

KEY IDEA

Tariffs can be designed to promote investment and achieve policy goals while limiting total costs to the 

public.

2.1.2 Auctions 

Auctions are a mechanism to contract for a known volume of new VRE power capacity. They have grown 

in popularity as a procurement and remuneration mechanism for VRE, especially in developing countries. 

The number of countries employing auctions—also known as tenders, demand auctions, procurement

auctions, or public competitive bidding—grew from 9 in 2009 to at least 44 by early 2013, including 30 

developing countries (IRENA 2013; REN21 2013). 

Key considerations for designing and implementing effective auctions are described in detail in Maurer & 

Barroso (2011). Further VRE-specific considerations and experiences from a wide range of national case 

studies are explored in Azuela & Barroso (2012) and IRENA (2013). IRENA (2013) suggests key

principles in auction design and implementation: 

Figure 2. Illustration of FIT CfD strike price 

(Source: DECC 2011)
7 

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• Selecting the type of auction (e.g. sealed-bid, descending clock, hybrid, and reverse auctions) 

considering their relative ease of implementation, ability to limit collusion, and ability to foster price 

discovery. 

• Determining auction volume with consideration of the capacity of the market to deliver. 

• Setting a ceiling price and not disclosing it to bidders in order to foster competition and price 

discovery.

• Ensuring streamlined administrative procedures, active communication, and transparency are

provided equally to all bidders. 

• Setting strong guarantees and penalties to prevent underbidding (e.g. bids that cannot later secure 

commercial financing), collusion, and project failures.

Finally, some observers note that the maturity of each specific VRE technology should be taken into 

account when considering auctions as a procurement option. For example, auctions may be most

appropriate for VRE technologies that are commercially proven and relatively close in cost to 

conventional technologies, such as wind power (Pérez-Arriaga 2013). 

2.1.3 Quotas and Targets

VRE quotas—either as stand-alone measures or as a complement to a procurement scheme—also 

represent a mechanism to procure a known volume of new VRE capacity. While VRE quotas are often set 

through policy rather than through regulation, they are nonetheless important framework conditions that 

guide the design of remuneration mechanisms (e.g. tariffs, auctions) that are commonly within the 

regulatory purview. Quotas are often utilized in concert with remuneration instruments. For example, in 

much of the United States where state-level renewable portfolio standards exist to create RE quotas, the 

federal production tax credit, which represents an “adder” tariff instrument,

7 is also available. In Europe, 

binding targets at the level of the European Commission exist alongside national remuneration 

mechanisms as well as the Emissions Trading Scheme. 

The various mechanisms described above can be employed alone or in concert. Their effectiveness in 

various combinations is beyond the scope of this report, but various researchers have examined this issue 

(see, e.g., Becker and Fischer [2013], Butler and Neuhoff [2008], Hiroux and Saguan [2010], Lauber 

[2004], and Mitchell, Bauknecht, and Connor [2006]). 

2.1.4 Interconnection Queue Management

The mechanisms above are the driving forces behind VRE deployment, but even when effective 

remuneration schemes are in place, VRE deployment rates can be constrained by licensing and

interconnection issues warranting regulatory attention. Some emerging approaches in these areas are 

discussed below.

Effective VRE procurement mechanisms typically result in a large number of grid connection 

applications that require evaluation in the context of limited grid capacity. This problem of queue 

management places an administrative burden on regulators and requires a fair mechanism for prioritizing 

grid connection applications. In some contexts, the regulator evaluates grid connections directly, while in 

other settings, the regulator sets the rules for evaluation to be performed by system operators. Applying a

‘first come, first served’ or pro rata allocation method (in which all applicants receive a reduced share of

their original bid) typically results in an economically inefficient outcome since applicants otherwise 

willing to pay more for scarce resources are not allowed to do so (ERRA and NARUC 2013). Instead, a 

more economically efficient outcome can be achieved through a competitive tender process in which 

interconnection capacities are tied to the applicants’ willingness to pay. Resulting offers—and associated 

 

7 An “adder” tariff instrument guarantees a premium rate for a specific energy source on top of the sale price for power.
8 

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income—can be used either to reduce consumer prices or to reinforce network capacity at key points 

(ERRA and NARUC 2013). 

A more administrative variation on the competitive tendering solution is the Irish Gate System. 

Historically, all wind generation applications were processed piecemeal in Ireland. As the number of wind 

farm applications grew in the 1990s and early 2000s, this ad hoc process became intractable due to 

competition for scarce grid capacity (Miller et al. 2013). It became clear that a more carefully designed

queue management method could allow for integration of more of the annual available wind energy with 

significantly less infrastructure development. In 2004, the Irish Commission for Energy Regulation 

directed the transmission system operator, EirGrid, to develop a new queue management protocol. The 

resulting “Gate System” or group-processing approach involves setting out criteria for each successive

batch of wind farms, which can then be processed as a single group. The procedure for each group 

generally involved setting a target wind power capacity (in MW), and then selecting candidate wind farm 

projects based on the submission date of each completed application as well as the assessment of system 

impact performed by the system operator. For more detail see CER (2008). 

KEY IDEA

Replacing ‘first-come, first-served’ grid connection processes with a more orderly and transparent process

based on system impacts can result in more efficient outcomes and provide more clarity to investors.

2.2 Grid Infrastructure: Early Stage Issues

The remote nature of some high-quality VRE resources can often require grid expansion, elevating the 

need for regulatory actions to minimize cost of new grid infrastructure through more coordinated planning 

approaches, and to adjust cost recovery mechanisms in line with policy goals and grid costs. This section 

explores some of the key concepts and emerging approaches in this domain.

2.2.1 Transmission Network Expansion 

At early stages, the regulation of transmission network expansion typically focuses on 1) supporting 

orderly project development so as to minimize overall network upgrade costs; 2) minimizing stranded 

resource risk8

 for VRE developers; and 3) appropriately allocating cost and risk of network connection 

and expansion among developers and ratepayers in accordance with policy goals. This latter point is 

important, as some jurisdictions prioritize rapid VRE deployment and thus enact regulatory frameworks 

that minimize the financial burden of network expansion to project developers. Such frameworks are 

commonly referred to as shallow or super-shallow frameworks (see Figure 3). 

 

8 Stranded resource risk can be defined as the risk that an infrastructure investment is under or unutilized. In the context of VRE 

developers, there may be a perceived risk that transmission capacity will not be available to carry power by the time the project is 

ready for commercial operation.
9 

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

In shallow and super-shallow regulatory frameworks, the regulator typically allocates most or all of the 

cost of network expansion to load. This has typically been the case in the European Union, and in 

particular in Germany and Denmark, where both have enacted super-shallow frameworks to reduce the 

burden to generators, particularly for offshore wind development (Scott 2007). In contrast, deep policy 

frameworks place more of the burden of network upgrades on the RE generator. For example, Mexico has 

traditionally placed responsibility for transmission expansion on generators. However, a process called 

“Open Season” allows for more efficient planning by the Mexican utility to reduce overall transmission 

costs. Deep policy approaches to network expansion will perhaps slow development but also reduce the 

financial burden to load. Below, the case of Australia illuminates these issues further.

2.2.1.1 Snapshot: Australia’s “Scaled Efficient Network Extension”

Challenge: While the government of Australia has been proactive in promoting VRE through both energy

and climate-related policy, the remoteness of VRE resources has posed a challenge for development. To 

address this barrier, the Australian Energy Market Commission (AEMC) proposed two options under the 

conceptual framework of “Scaled Efficient Network Extension” (SENE) in which upfront costs are 

minimized through economies of scale and cost-sharing. The two options varied mainly in how costs and 

risks were allocated. Each option, described below, posed further challenges associated with possible 

stranded resource risks. 

Proposed Solutions: Under the first proposed SENE option, consumers would pay the majority (75%) of 

upfront costs associated with transmission extension and would be reimbursed as more generation came 

online in the future. While transmission extension decisions would be based on analysis of interest in the 

market and projected future generation in the proposed geographic area, the consumers would still take on 

the majority of risk associated with the potential for stranded resources if further generation development 

did not come to fruition. Under the second SENE option, RE generators or investors would pay the 

upfront costs to extend transmission taking on the possible “stranded resource” risk noted above. Similar 

to consumers, the early generators and investors paying the upfront cost would ideally be reimbursed as 

new generators came online. 

Outcome: The AEMC, concerned that consumers would be least equipped to deal with stranded resource 

risk, elected the second option to finance transmission extension. AEMC cited that analysis projecting 

future generation was not robust enough for consumers to take on the risk and that generators and 

investors would have “better information, capability and incentive to weigh the benefits of scale 

efficiencies versus stranding risk.” In this regard, AEMC enacted a “semi-deep” policy, allocating risks to

Figure 3. Classification of transmission network cost allocation policies

Source: Madrigal and Stoft (2011)
10 

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VRE developers based on the idea that they are best able to price these risks. This choice reflects the 

broader policy approach in Australia, where new VRE generation planning is largely market-based and 

“there is no mechanism to force any particular outcome and any decision to invest in new generation is 

entirely the responsibility of the investing party” (Cochran et al. 2012, p. 41). Therefore, private 

generators are assumed to have the best information and data, as national-level planning processes are 

largely indicative and only intended to provide high-level information on economically feasible VRE 

areas. The SENE example is discussed in greater detail in (ICER 2012). 

KEY IDEA

In cases where there is plausible risk of stranded transmission assets, one common risk management 

model is to place the risk on parties best able to evaluate and manage it. 

2.2.2 Network Usage Costs

In addition to network expansion costs, the allocation of network usage costs (alternately known as “use 

of system” or UoS costs) also impacts the revenue streams to VRE generators. Generally, methods to 

allocate costs of network usage fall into one of two camps: ‘postage stamp’ and ‘flow-based’ methods. 

Under the former, the transmission system user pays the same rate regardless of the source or destination 

of the electricity, or of the costs and benefits of the generator’s production. Like sending an in-country 

letter with a postage stamp, price is not linked to the sending or receiving location (Hempling 2009, 

Madrigal 2012). Under flow-based methods, also known as “pancaking,” transmission system users are 

charged according to level of use, usually defined according to some engineering proxy of the path that 

electrons take to their final destination. (An engineering proxy is required since it is physically impossible 

to trace individual electrons on a grid.) Mathematical formulations for both postage stamp and various 

flow-based methods are discussed in depth in Madrigal (2012). In some cases, VRE generators are not 

charged any network usage cost at all, for example, in Spain, Germany, India (solar only), and Texas 

(Madrigal 2012). 

Given that VRE resources are geographically specific, and that geographic diversity of VRE resources is 

generally beneficial to system operation because it reduces aggregate variability and uncertainty, the 

design of network usage costs takes on increased importance in the shift to high VRE penetrations. 

Generally speaking, postage stamp methods reduce the financial burden of network usage on VRE 

generators while flow-based methods increase them. Analysis by Madrigal (2012) explores the dual role 

played by network connection cost charge and the network usage cost in the final levelized cost of 

electricity (LCOE) for a basic 50-MW wind farm. The combination most favorable to the generator—zero 

connection costs and zero usage costs—resulted in an LCOE approximately 15% lower than the least 

favorable— a flow-based usage cost and a semi-deep connection cost that included costs of the 

transformer and the connection line (not upgrades to the substation), along with a flow-based usage cost. 

While 15% may not appear substantial, it can represent a very large percentage of a premium tariff, so the 

treatment of network connection and usage charges is an important complement to tariff design. 

Thorough discussion of this topic can be found in Madrigal (2012), Scott (2007), and Pérez-Arriaga 

(2013). 

KEY IDEA

Network usage charges can significantly alter VRE project economics and can be designed to advance 

policy goals. 

2.2.3 Distributed Generation Network Interconnection

At all levels of penetration, ease of interconnection of distributed generators at the medium- and lowvoltage networks is recognized as one of the key non-cost factors that influence rates of distributed RE 

deployment. During early stages, jurisdictions seeking to accelerate VRE deployment typically focus on 

reducing barriers posed by interconnection rules. The terms of grid interconnection are often in the 

purview of regulators (although they are typically shared with grid operators and international standards 
11 

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bodies), and thus represent an important way to reduce barriers to deployment. The cases of Hawaii and 

Guatemala shed some light on typical issues that arise in this area.

2.2.3.1 Snapshot: Hawaii Solar Interconnection, Part 1

Challenge: With high energy prices and favorable solar resources, Hawaii aims to substantially increase 

PV deployment. However, complex legacy interconnection procedures and licensing processes can 

present significant non-economic barriers to solar PV development and implementation, frustrating policy 

goals. 

Solution: To reduce non-economic barriers to PV deployment, in 2008 the Hawaii Public Utility 

Commission issued decisions to simplify the grid interconnection process for small-scale renewables.

Among other elements, the new rules simplify the application process; streamline interconnection 

procedures, guidelines, and net-metering agreements; and establish timelines for interconnection 

requirements, including time needed to resolve any disputes related to projects. A subsequent decision in 

2011 limited the number of projects that need to provide an Interconnection Requirements Study (IRS). 

Details of Hawaii interconnection procedures can be found at DSIRE (2012). Part 2 of this snapshot, 

which discusses technical issues encountered with very rapid PV deployment, is found in Section 3. 

KEY IDEA

Simplifying interconnection procedures for distributed resources is often complementary to other 

procurement mechanisms such as policy targets and specialized tariffs. 

2.2.3.2 Snapshot: Guatemala Distributed RE Interconnection

Challenge: Interest in RE in Guatemala has been driven by relatively high reliance on energy imports and 

persistently low energy access. Despite these drivers and policy incentives, interconnection processes and 

technical standards were criticized as unclear by various market actors, frustrating the goal of rapid RE 

deployment, especially distributed hydro resources below 5 MW.

Solution: In 2006, the regulator, the Comisión Nacional de Energia Eléctrica (CNEE), embarked on a 

series of reforms to clarify interconnection rules and technical standards. The resulting amendments to the 

General Electricity Law elaborated a set of rules (“DRG Rules”) that clarified the definition of distributed 

renewable generation (DRG), compelled distribution companies to allow interconnection of RE 

generators below 5 MW conditional upon adequate modifications to interconnection capacity, and 

mandated that distributors purchase electricity at wholesale market prices, if not already contracted by 

another party. DRG Rules also clarified that if an interconnection necessitated modification or expansion 

of the network, the RE generator would bear the cost. Finally, the DRG Rules gave CNEE the explicit 

authority to regulate the connection, operation, control, and marketing conditions of distributed RE.

In tandem with the DRG Rules, which clarified the legal and regulatory issues of DRG connections, 

CNEE promulgated a technical standard for interconnection to improve the quality of power delivered 

from distributed resources. This standard (“Norma Técnica para la Conexión, Operación, Control y 

Comercialización de la Generación Distribuida Renovable”) was based in part on technical references of 

the IEEE 1547 Standard (“Standard for Interconnecting Distributed Resources with Electric Power 

Systems”) to clarify minimum protective equipment for RE plants below 5 MW. For a more detailed 

exploration of the Guatemala experience, see NARUC (2011). 

KEY IDEA

Harmonizing interconnection procedures with robust technical standards can encourage investment while 

maintaining reliability.

Beyond the issues of interconnection, queue management, and siting, other more substantial grid 

reinforcement issues are rarely critical at the early stage of VRE deployment. In jurisdictions where all 

high-quality resources are remote, or where systems are very small, isolated, or weak, even small
12 

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additions of VRE may challenge existing grid infrastructure. However, in such cases, grid infrastructure 

concerns would not be unique to VRE, but would extend to all forms of generation. For further reading on 

such settings, various IRENA reports have focused on the issues of grid reinforcement of small systems, 

such as IRENA (2012). 

2.3 Flexibility and Resource Adequacy: Planning for the Future 

Although each system is different, given the relatively minor impacts on system operation and overall 

fleet composition at early stages of VRE deployment, substantial regulatory changes are rarely required 

with regard to either system flexibility or resource adequacy. These early stages are, however, a critical 

time to begin to plan for these issues, and to collect data that will support regulatory and policy decisionmaking at intermediate and advanced stage stages. These data are crucial to support more thorough 

analyses (such as formal grid integration studies, discussed in Section 3) that later will be important for 

exploring key issues such as transmission and reserve capacity needs, market design modifications, and 

flexibility requirements. Such data requirements are discussed in detail in IEA WIND (2013b) and may 

include: 

• Historic load data. Multiple years of historic load data are important for understanding the temporal 

patterns of load. These will be important considerations for understanding reserve requirements under 

future VRE scenarios, as well as for understanding the capacity credit contributions of VRE.

• Power plant data. Historic data of power plant generation, and about power plant capabilities, are 

critically important to accurate grid integration studies. Key performance factors for power plants 

include ramp rates, minimum generation levels, heat rates as a function of load, and emissions rates. 

To the extent hydro plants constitute a significant resource, important data include storage levels, 

water inflow, and any non-power constraints on generation, such as agricultural use or ecological 

protection. 

• Multiple years of wind and solar resource data. Robust grid integration studies will require multiple 

years of solar and wind resource data. It takes multiple years to collect VRE resource data, and wind 

data--in contrast to solar--is typically more difficult and costly to measure and model. Data for both 

resources will ideally be at high spatio-temporal resolution, and will span multiple historic weather 

years in order to capture year-to-year weather cycles (such as La Niña/ El Niño) and related

correlations between wet/dry years, hydro power production, and biomass production insofar as they 

are of interest. 

Further discussion of these and other data requirements can be found in IEA WIND (2013b). Finally, a 

practical consideration discussed in that report is the establishment of a leadership team to carry out grid 

integration studies, including a lead agency supported by a study guidance committee to facilitate 

participation by critical stakeholders. Depending on the planned rate of VRE deployment, these issues can 

warrant regulatory consideration during the early stage. 

In addition to grid infrastructure issues, the next two sections explore further the flexibility and resource 

adequacy issues as they grow in importance at intermediate and advanced stage VRE penetration. 
13 

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3 Intermediate Stage Regulatory Issues

Beyond the early stages of deployment, regulatory priorities expand to include more systemic effects at 

intermediate stages, such as efficient large-scale grid expansion and total power system flexibility. This 

section explores a sampling of lessons learned in these more complex issues.

3.1 VRE Procurement: Intermediate Stage Issues

Implemented well, the VRE procurement concepts outlined in Section 2.1 will also largely satisfy 

regulatory requirements at intermediate stages. Especially important are remuneration schemes that 

balance system-specific requirements, public policy goals, and financial constraints as VRE penetration 

grows. Similarly, queue management will be equally important at the intermediate stage. 

3.2 Grid Infrastructure: Intermediate Stage Issues

As deployment rates reach intermediate levels, a more coordinated regulatory approach to network 

expansion and reinforcement can be needed. 

3.2.1 Transmission Network Expansion

After the closest utility-scale VRE generation sites have been developed during the early stages, 

regulatory issues at intermediate stages can focus on facilitating access to increasingly remote locations, 

which has important ramifications for resource quality and network expansion cost and complexity. As 

such, this issue is closely related to queue management (discussed in Section 2.1.4) since a transparent 

and orderly process for siting can reduce project development risk and costs. Broadly speaking, the role of 

regulators in supporting efficient transmission planning grows along with VRE deployment since 

uncoordinated VRE siting can result in suboptimal solutions (Madrigal 2012). Innovative approaches to 

transmission planning are discussed in RAP (2013b). The case of Texas provides one emerging approach 

to this issue. 

3.2.1.1 Snapshot: Texas “Competitive RE Zones”

Challenge: High-quality wind resources in Texas are distant from large load centers. In this context, 

uncertainty around the level and timing of public investment in transmission can make it difficult to 

attract VRE project development. Also, transmission investments in the United States typically follow 

wind generation proposals and are contingent upon commitments from generators to use the lines, posing 

a classic chicken-and-egg dilemma. Finally, transmission extension can take up to a decade while 

deployment of VRE generation often only takes up to a few years, creating challenges around 

incongruence of investment timing. To address these challenges and in order to meet state energy goals, 

regulators sought to spur development while appropriately balancing risk between the public and private 

sectors. 

Solution: Texas Senate Bill 20 mandated the Public Utility Commission of Texas (PUCT) to identify 

Competitive Renewable Energy Zones (CREZ) in the state (Texas Senate 2005). The PUCT worked with 

transmission providers to design detailed transmission extension and upgrade plans for feasible and 

competitive wind generation areas (Figure 4). The transmission plans focus on long-term infrastructure 

needs, e.g., constructing higher voltage lines, which will lead to greater transmission efficiencies over 

time (PUCT 2010). 
14 

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Notably, Texas Senate Bill 20 also set forth a funding structure authorizing CREZ transmission 

investments to be financed by utility customers. This authorization guaranteed cost recovery for 

transmission investors, reducing risk and addressing the chicken-and-egg dilemma noted above. 

The CREZ process also involved intensive stakeholder consultations that informed final decisions on 

wind project and transmission siting. Issues that often raise public concern, such as line extension, were 

mitigated by ensuring active stakeholder engagement and facilitating multiple opportunities for feedback, 

thus increasing efficiency and speed of the process. Primarily routing transmission lines over private land 

rather than federal land (which requires compliance with the National Environmental Policy Act and a 

larger number of stakeholders), basing choice of CREZ locations on wind developer interest, and focusing 

Figure 4. "Competitive RE zones" and related transmission lines in Texas 

Source: SNLFinancial (2013)
15 

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

public stakeholder feedback on transmission line location also contributed to an efficient and timely 

process (Cochran et al. 2012). 

KEY IDEA

Transmission expansion costs can be minimized through coordinated planning processes that identify 

high-quality resource areas, address investment risk through funding structures that ensure cost 

recovery, and engage stakeholders throughout the process.

Aside from the above issues of efficiency and timeliness, RE project siting in developing countries can 

raise additional complexities, such as ensuring equitable terms in site procurement. For example, in many 

developing country settings, existing tenants may not have full land rights or may not know the fair 

market value of their land. In either case, if handled inappropriately, VRE siting and land acquisition 

practices can exacerbate existing inequities around land use. For more on this issue, see Ledec, Rapp, and

Aiello (2011). 

3.2.2 Distribution Network Development

The rapid growth of VRE on distribution networks (especially distributed PV) is raising the importance of 

regulatory treatment of distribution networks. Investments in distribution and transmission networks 

differ from each other in several important ways, especially in terms of the number and cost of projects, 

planning periods, and “lumpiness” of annual budgets, among other factors (Petrov 2013). Figure 5

illustrates some of these differences. 

Figure 5. Investment properties of transmission and distribution networks

Source: Adapted from Petrov (2013)

Distribution network regulatory issues involve substantive, procedural, and public interest questions. 

Substantive issues focus on accurately assessing the impact of VRE production on distribution networks. 

Procedural issues include determining appropriate modifications to distribution networks, minimizing 

their costs, and appropriately allocating these costs. This final step of allocation involves questions of 

public interest. Deep policies (allocating all network reinforcement costs to generators) will slow 

deployment but limit the cost to utilities and the public while shallow policies will accelerate deployment 

but require allocation to specific parties. 

Increasing penetrations of VRE—especially solar PV—challenges existing models of distribution 

network regulation and operation. Distribution networks have historically been, and continue to be, 

designed to accommodate peak demand. In some locations, PV can reduce these peaks, yet in many 

regions peak demand occurs in the evening or in the winter, when solar PV production is absent or 
16 

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reduced, so the overall network cost is not reduced and may even increase (Eurelectric 2013). Figure 6 

illustrates how in the span of 3 years, PV installations in the region of Puglia, Italy have nearly 

eliminated—and in some cases, reversed—power flows from the transmission network to the distribution 

network, creating occasional “backflow” conditions during the middle of sunny, springtime weekend 

days. At the same time, these new PV penetrations have left the evening peak unchanged, leading to a 

steep ramp in the afternoon (Eurelectric 2013). Substantively, the answers to questions about PV impact 

on distribution network production and loading need to be answered through detailed grid integration 

studies at high temporal and spatial resolutions. 

Figure 6. Power flows between transmission and distribution network in the Puglia region of Italy, 

2010–2012

Source: Enel Distribuzione in Eurelectric (2013)

In addition to its impacts on peak demand requirements beyond certain penetration levels on distribution 

networks, VRE may contribute to additional need for grid reinforcement due to voltage variation and 

congestion (Eurelectric 2013). The precise penetration levels at which grid reinforcement may be required 

are highly sensitive to existing grid configuration. Additionally, innovative grid reinforcement and 

protection schemes are an active area of technical, policy, and regulatory research. The case studies of 

Hawaii and Germany may shed light on some of these issues. 

3.2.2.1 Snapshot: Hawaii Solar PV Interconnection, Part 2

Update: Favorable incentives, falling PV costs, simplified interconnection processes, and very high 

electricity prices have combined to produce very rapid growth in PV deployment in Hawaii. As discussed 

in Section 2, a 2011 Hawaii PUC decision sought to relax requirements of PV interconnection studies. 

After this decision, utilities essentially guaranteed interconnection for residential systems with capacity 

less than 10 kW. 
17 

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Under these conditions, the largest 

utility in Hawaii, Hawaiian Electric 

Company (HECO), observed rapid solar 

deployment after 2011. By 2013

approximately 10% of utility customers 

had installed PV compared to 

approximately 3% in California 

(Mulkern 2013). In 2013, HECO 

established new interconnection review 

study (IRS) processes, mandating an 

IRS for all systems up to 10 kW on 

circuits where total PV capacity exceeds 

100% of “daytime minimum load” or 

DML (see Figure 8).9 This threshold 

was later increased to 120% of DML in 

February 2014 (“Transient Overvoltage 

Mitigation” 2014). The percentage-ofDML threshold is based on the system 

operators’ assessment of reliability and 

safety concerns from PV backflow, and 

the requirement for interconnection 

studies has dramatically limited new interconnections on the island, which in turn has prompted a 

regulatory response. On April 28, 2014, the Hawaii PUC released an order (PUC of Hawaii 2014), 

articulating the following concerns, among others:

• That HECO “failed to anticipate the rapid growth in distributed solar PV interconnections, and thus 

did not proactively plan and manage the distribution circuit interconnection process or technical 

challenges” (“Transient Overvoltage Mitigation” 2014, p. 91). 

• That there is a lack of transparency regarding status of interconnection applications and the 

interconnection review process itself.

• That the DML metric is imprecisely measured.

The Hawaii PUC ordered HECO to develop a formal, transparent, unified distribution system 

interconnection queue. Every distribution circuit will have its own queue with technical information and a 

waiting list (with timelines) for when IRSs will be completed. HECO will be required to file monthly 

reports with extensive information on all interconnection requests and IRSs they say are required, and 

must also explain why there are delays in performing any scheduled IRSs. Regarding the measurement of 

DML, HECO will now be required to develop and implement an “ongoing distribution circuit monitoring 

program” to measure real-time voltage and other power quality parameters (e.g., voltage fluctuations and 

flicker, voltage during transient events, harmonics, etc.). This approach aims to establish a data-driven 

and transparent approach to IRS requirements.

The Hawaii story raises a trio of regulatory questions—substantive, procedural, and public interest—that 

are applicable to other settings with growing shares of distribution-level PV deployment. Substantively, 

what are the actual system reliability impacts of high penetrations of PV, what grid reinforcements will 

allow for greater penetrations of PV today and in the future, and what will such reinforcements cost? 

Procedurally, at what point can distribution system operators (DSOs) independently place restrictions on 

PV interconnection due to system reliability concerns? Also, if grid reinforcement is required for system 

reliability, how can costs be minimized, for example through coordinated planning, and how should they 

 

9 There is some debate over the appropriate calculation of daytime minimum load. See "Hawaii Solar Voices" (2013).

Figure 7. February 2014 "Locational Value Map" of Oahu, 

illustrating PV penetration as a percent of daytime minimum 

load 

Source: HECO (2014)
18 

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be allocated? With regards to the public interest, to what extent are additional expenditures on grid 

reinforcement justified by public policy goals of PV deployment? 

As Hawaiian regulators and utilities grapple with PV deployment, planning, and grid reinforcement 

needs, they may find useful lessons to be learned from Germany, the focus of the next snapshot. 

3.2.2.2 Snapshot: Facilitating PV Integration Through Mandated Grid Services in 

Germany

Challenge: Over the past 15 years, Germany led new annual solar capacity installations globally.10 As of 

November 2013, more than 35 GW of solar PV was installed in Germany, and annual generation in 2013 

exceeded 29.7 TWh (Fraunhofer Institute for Solar Energy Systems 2014). On Sunday, July 7, 2013, 

German PV output peaked at nearly 40% of instantaneous demand and provided approximately 21% of 

total daily generation (Gerke 2013). While Sundays are typically low-demand days, these types of events 

will likely be more common as PV capacity continues to grow. 

In this context, German regulators have been tasked with ensuring the quality and performance of the 

electricity system. While HECO currently caps PV deployment on any given circuit at 100% of daytime 

minimum load distributed, in southern Germany, DSOs have not established such caps, and PV output 

commonly represents a majority of local maximum load and, in many cases, exceeds it by multiple times 

(Eurelectric 2013).

11 In such instances, distribution networks are in a backflow state and appear as a large 

generator to the transmission system operator (TSO). 

Solution: A number of operational practices, grid codes, technical standards, and control schemes have 

been established by German policymakers, regulators, and standards bodies to ensure that PV supply 

supports grid reliability.12 Feed-in management is one such operational practice. In Germany, the DSO 

has active management of PV installations over a certain size, which allows for the technical ability to 

curtail production as needed. PV installation owners can either choose to install a communication device 

that allows for direct feed-in reduction by the DSO, or can choose to reduce the feed-in power to 70% of 

the nameplate capacity. This arrangement leads to greater control for the DSO and overall higher levels of 

connection to the network since new installations can be added without immediately incurring the need 

for large-scale reinforcement. But this arrangement also leads to the loss of about 5% of energy to the 

system. In Germany, installation owners are compensated for lost production and these costs are 

socialized (Eurelectric 2013). 

In addition to feed-in management systems, the Medium and Low Voltage Directives mandate hardware 

requirements for PV systems which enable operators to provide grid services; these include inverters with 

control algorithms to address frequency and voltage variations and devices which enabled PV installations 

to dynamically curtail outputs to support grid stability (Stetz 2012). These investments defer larger grid 

reinforcement costs, and can be viewed as providing option value, allowing time for grid reinforcement 

schemes and technologies to evolve, and for their costs to drop (Miller et al. 2013).

KEY IDEA

Distribution grid concerns at intermediate and high VRE penetrations can be mitigated through advanced

grid codes and allowance for strategic curtailment of VRE. 

 

10 The United States was forecasted to take over the lead in PV installations in 4th quarter of 2013 (Munsell 2013). 11 Germany is not the only example. For example, in Galicia, Spain, the capacity of distributed generation sources connected to 

the distribution network exceeds 120% of peak demand. The sources are varied however, including wind, combined heat and 

power (CHP), hydro, and PV, so the variability and uncertainty is less than with only PV (Eurelectric 2013).

12 Specifically, these codes were developed by the German Association for Electrical, Electronic & Information Technologies 

(VDE) and the German Association of Energy and Water Industries (BDEW).
19 

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3.3 Flexibility: Intermediate Stage Issues

At intermediate penetrations, VRE may begin to exert more noticeable demands on power system 

flexibility, which is the ability of the power system to respond to changes in supply and demand. Power 

systems are all flexible to some degree, historically driven by demand fluctuations, ramping constraints 

and outages of conventional generators. Growing VRE generation increases the need for power system 

flexibility; some systems may easily absorb VRE fluctuations while others may require earlier attention

and in some cases, regulatory action. This section discusses some of the key issues in understanding 

flexibility needs at the intermediate stage of deployment. 

3.3.1 Estimating Reserve Impacts of VRE

In systems with sufficient capacity, system operators typically hold additional generation capacity in 

reserve to address contingency events (such as the loss of a generator or transmission line) and 

accommodate normal fluctuations in demand. As VRE grows, changes to reserve requirements may 

become necessary. Many system operators further hedge against additional variability and uncertainty by 

holding additional reserves. Recent analysis suggests, however, that wind and solar generation tends to 

free up other generation capacity in proportion to its production, thus canceling out some or all of the net 

cost of additional operating reserves (Hummon et al. 2013). 

Thus key substantive questions arise, namely how much capacity (and of what performance 

characteristics) needs to be held in reserve for reliability. Answers to these questions can impact the 

system-wide cost of integrating large amounts of VRE generation. The substantive issues involved in 

assessing adequate reserves under growing VRE shares are technically complex; for more detail see 

Doherty & O’Malley (2005), Ela, Milligan, and Kirby (2011), Hummon et al. (2013), and Morales, 

Conejo, and Perez-Ruiz (2009). 

In light of these substantive questions, procedural changes may also be required as VRE penetrations 

increase—for example, modifications to reserve planning methodologies. Regulators may require that a 

system operator performs enhanced analysis to gain a clearer picture of required system flexibility in light 

of anticipated amount, composition, and location of new VRE generation. Additionally, regulators may 

re-assess the planning procedures that determine allowable risk of reliability events due to reserve 

shortfalls. IEA WIND (2013) recommends utilizing existing operational requirements for reliability risk

when developing planning scenarios (such a requirement may state, for example, that the system is able 

cover 95% of the variations in load and net load.) 

While establishing reliability risk tolerance is typically within the regulatory purview, estimating specific 

reserve requirements of future scenarios more typically falls to the system operator. Nonetheless, 

determining which resources qualify to provide reserves (e.g., DR) and how these reserves are obtained

are important regulatory responsibilities. Appropriate strategies depend strongly on the market and 

regulatory framework. For example, vertically integrated utilities may simulate reserve requirements and 

propose capital investment based on estimated reserve changes, requiring careful technical review by 

regulators. In contrast, in organized wholesale market settings the approach typically falls into the larger 

question of ancillary services market design, which determines the types of ancillary services required 

and prices paid to generators (or demand-side resources) that provide them (RAP 2013c; Cochran et al.

2013). 

International experience has generally revealed that reserve requirements can be reduced through a 

variety of ‘soft’ measures. These include system operational measures (such as improving forecasting and

implementing faster scheduling), institutional measures (such as expanding balancing areas and

coordinating reserve sharing with adjacent balancing areas), and planning measures (such as incentivizing 

geographic diversity of wind and solar resources)(Cochran et al. 2012). These measures are discussed in 

this section and in Section 4.
20 

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

3.3.2 Forecasting

In concert with market rules and system operation protocols, high-quality forecasting reduces uncertainty 

about the level of reserve capacity that needs to be held at any given time, and thus reduces reserve 

requirements in the aggregate. The specific requirements placed on system operators and generators to 

employ forecasting are often the purview of regulatory agencies. The case of Germany provides one 

perspective on this issue.

3.3.2.1 Snapshot: Reducing Reserve Requirements Through Better Forecasting in 

Germany 

Challenge: With increasing levels of both wind and solar generation in Germany, system operators face 

increasing probability of significant variability events, elevating the importance of efficient reserve 

management. 

Solution: The government of Germany mandated state-of-the art forecasting techniques to support grid 

reliability with increasing variable resource integration. German transmission system operators (TSOs) 

use a number of forecast outputs from various models to combine and produce optimal forecasts that also 

take into account current weather patterns. This approach is advantageous as different models often have 

better prediction outputs for certain weather conditions and combining these outputs can create a more 

accurate and robust forecast to support electricity planning. Based on the modeling outputs, the forecast 

amount is sold by TSOs to day-ahead and intra-day spot markets. Using this technique, the average 

forecast error is 4.5% for day-ahead predictions (Review of Industry Practice 2012). As highlighted in 

Germany, advanced forecasting methods can be valuable in ensuring reliability of the electricity system. 

Regulators may have the opportunity to support and direct TSOs in choosing forecasting techniques that 

enhance efficiency across the power system. 

KEY IDEA

Reserve requirements can be reduced through advanced forecasting techniques and effective integration 

of those techniques into power system operation.

3.3.3 Improving System Operation Practices

Increasingly, system operation practices are recognized as tools to manage VRE flexibility requirements, 

thereby reducing integration costs. For example, systems that establish hourly (or less frequent) dispatch 

intervals effectively strand significant flexibility. Under hourly scheduling, because wind and solar 

resources exhibit variability on time frames shorter than an hour, all intra-hour changes must be managed 

through reserves, which are typically more expensive. In contrast, energy markets running dispatch and 

schedule changes every 5-15 minutes substantially increase the ability of the system to manage higher 

penetrations of VRE at less cost (Milligan et al. 2011). Most major organized markets in the United States

employ five-minute scheduling (DOE SETP 2011) while the German market employs 15-minute 

scheduling intervals (ICER 2012). 

The case of the U.S. Federal Energy Regulatory Commission (FERC) approach to supporting VRE 

integration provides one perspective on these issues. 

3.3.3.1 Snapshot: U.S. Federal Energy Regulatory Commission Order 764 

Challenge: In the United States, operational practices for addressing electricity system variability and 

related ancillary services were established when generation was sourced predominantly from 

conventional, dispatchable electricity resources. Thus, historically, load fluctuation was the predominant 

source of intra-hour variation. VRE can contribute to additional intra-hour variation, and conventional

system operation practices were resulting in discriminatory treatment of VRE generators, suboptimal 

system operation, and increased costs to consumers (FERC 2012). 
21 

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

Solution: To address this challenge and advance system operation practices, FERC promulgated Order 

764 in 2012. This order encompassed a wide range of measures, first revising the Open Access 

Transmission Tariff (OATT) to give transmission customers the ability to adjust intra-hour transmission 

schedules, a measure particularly beneficial given the intra-hour variability of VRE. Second, the order

revised the Large Generator Interconnection Agreement (LGIA) to allow transmission providers to 

request forecast-relevant data from wind and solar resources for the purpose of developing and using 

power production forecasts. Additionally, Order 764 clarifies that transmission providers are only allowed 

to require this data if they are charging a differentiated rate for ancillary services. In effect, Order 764 

bounded the types of data transmission providers can request from generators, and required that these 

requests had to match the level of forecasting being conducted. 

Order 764 reforms aimed to reduce potential discriminatory system operation practices while providing 

transmission operators the necessary data to accurately forecast total wind output on their systems, 

resulting in more efficient management of variability and uncertainty. These matters are discussed in 

detail in FERC (2012). 

KEY IDEA

Changes to system operational and forecasting methods can be combined to unlock physical flexibility 

and enhance system reliability under growing shares of VRE.

In Focus: Grid Integration Charges

In some jurisdictions, grid integration charges have been levied on VRE generators as a mechanism to 

recoup costs associated with system balancing. Other jurisdictions have explicitly opted against such 

charges, holding that they break from the traditional practice of socializing balancing costs across all 

customers. This section briefly explores some regulatory issues involved in assessing whether and how to 

assess grid integration charges. 

When conducting regulatory cost-benefit analysis for VRE additions, complexity arises in accurately 

assessing and allocating both costs and benefits. On the cost side, precise VRE integration costs are 

difficult to assess, might change over time, might be higher or lower depending on system characteristics, 

and will depend significantly on the accounting methods used. Furthermore, whether to fully socialize 

these costs or to assess charges to specific network actors also depends upon the regulatory and policy 

context. The regulatory treatment of these costs will impact the investment landscape for VRE 

deployment, so advancing the state of knowledge in this area is of keen interest, especially given 

continued policy commitments to larger VRE contributions to power systems.

Because regulators do not directly observe the components of VRE integration costs, classic issues of 

regulation arise, namely attempting to overcome information asymmetries in order to produce results that 

might otherwise emerge from efficient, competitive markets. In practice, regulators administratively set 

the prices of goods and services for which natural price discovery is difficult or impossible and attempt to 

produce the most fair and efficient outcomes. Such regulatory efforts strongly shape market functioning 

and outcomes, in electricity systems generally and in VRE integration in particular.13 

Administratively setting integration charges requires a comprehensive understanding of the nature of grid 

functioning, and furthermore requires tailored processes that seek to meet policy mandates fairly and 

efficiently. Regulatory determinations based on incomplete or faulty information, or based on faulty 

stakeholder engagement processes, can impede VRE development (e.g., in the case of onerous integration 

 

13 Various characteristics of power systems inhibit naturally-occurring efficiency and competition. See, for example, 

Joskow and Schmalensee (1983), Kahn (1988), and Stoft (2002). Over the past 30 years, however, experiments in 

power market restructuring have revealed the potential for much greater competition than was thought possible 

through most of the 20th century. Even in restructured markets, however, the role of regulators is significant. See, for 

example, Joskow (2002) and Joskow (2003).
22 

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

charges), or degrade system reliability or market functioning (e.g., in the case of failure to address VRE 

integration as an issue). 

Estimating integration costs accurately—and assigning them fairly—is not a straightforward task. For 

example, to date there is no single globally accepted method for calculating VRE integration costs

(Milligan et al. 2011), and given the significant uniqueness of power systems, a global “standard model” 

of estimating integration charges is unlikely to emerge soon. VRE integration costs are idiosyncratic, and 

the difficulty in estimating and allocating them derives from various factors:

• Determining integration costs directly attributable to VRE requires a comparison to some “reference 

case” scenario, and the specification of that reference scenario will significantly impact the resulting 

estimates of integration charges (Milligan et al. 2011). 

• Given the nature of power system economics, precise attribution of causation of integration costs is 

often difficult and dependent on characteristics of the generation portfolio online, complicating the 

process of cost allocation.

• The least-cost path to VRE integration is unique to each power system, and is typically a product of 

“learning-while-doing.” In such a context, it is difficult for regulators to accurately predict integration 

costs. 

• RE confers social and system benefits in addition to incurring system costs, so holistic benefit-cost 

analysis may impact the final estimated cost of VRE integration.

• The patterns of future deployment of VRE and other relevant system assets such as networks and 

demand-side resources will impact final integration costs. Since these are difficult to predict with 

precision, ex ante integration charges may over- or understate actual costs. 

• Multiple actors advocate for diverging approaches to VRE integration, each with different system 

implications into the future, and so problems of advocacy and “picking winners” further complicates 

the accurate development of integration charges. 

Improving the regulatory understanding of VRE integration can help resolve some of these issues, but 

others are inherently difficult to overcome. In this context, socializing integration costs across all 

customers is a common regulatory option, as it aligns with historical practice and avoids the complexities 

of determining specific costs and levying charges appropriately. 

3.4 Resource Adequacy: Intermediate Stage Issues 

Generation adequacy is the ability to deliver sufficient capacity to meet electricity demand at all times in 

the future.14 VRE generation contributes to this ability, although the precise contribution is highly 

dependent upon system characteristics. Generally, VRE capacity contributions—or capacity credit —are 

less than those of conventional dispatchable power plants. Technical formulations of the capacity credit 

question have evolved over the past decade and are discussed in detail in Keane et al. (2011), and 

Milligan and Porter (2006). While inadequate generation adequacy uniquely due to VRE has not been 

documented at intermediate levels of VRE penetration, at today’s intermediate stage in Europe, there are 

contested debates underway about the impacts (both current and anticipated) of VRE generation on the 

financial health of conventional generators (ACER 2013). This section examines some of these issues in 

both contexts of excess capacity (found in most OECD nations) and capacity scarcity (found in many 

emerging economies). 

 

14 In more technical terms, generation adequacy measures the capability of the power system to supply aggregate demand in all 

the states in which the power system may exist considering standard conditions (European Commission 2012). 
23 

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

3.4.1 Adequacy Mechanisms

Adequacy is ensured through a wide variety of mechanisms. Table 2 summarizes international 

approaches—both administrative and market-based—to address resource adequacy. Further information 

and exploration on these examples can be found in Spees, Newell, and Pfeifenberger (2013). 

Table 2. Administrative and Market-based Constructs for Adequacy

Administrative Mechanisms

(Customers Bear Relatively More Risk)

Market-based Mechanisms

(Suppliers Bear Relatively More Risk)

Regulated

Utilities

Administrative

Contracting

Capacity

Payments

LSE RA

Requirement

Capacity

Markets

EnergyOnly

Markets

Examples SPP, BC

Hydro, much 

of 

WECC and 

SERC

Ontario Spain, South

America

California,

MISO (both 

also have 

regulated IRP) 

PJM, NYISO,

ISO-NE, 

Brazil,

Italy, Russia 

ERCOT,

Alberta, 

Australia’s 

NEM, 

Scandinavia

Resource 

Adequacy 

Requirement?

Yes (Utility 

IRP) 

Yes

(Administrative 

IRP)

Yes (Rules 

for 

Payment Size 

and Eligibility)

Yes (Creates

Bilateral 

Capacity 

Market)

Yes 

(Mandatory 

Capacity 

Auction)

No (Resource

Adequacy not 

Assured)

How are 

capital costs 

recovered?

Rate 

Recovery

Energy Market

plus 

Administrative 

Contracts 

Energy 

Market 

plus Capacity 

Payments

Bilateral

capacity 

payments plus 

Energy Market

Bilateral 

capacity 

payments plus 

Capacity and 

Energy 

Markets

Energy Market

Source: Adapted from Spees, Newell, and Pfeifenberger (2013)

The ongoing debates in Texas and the United Kingdom over appropriate regulatory approach to resource

adequacy provide two contrasting perspectives on this issue.

3.4.1.1 Snapshot: Resource Adequacy Debates in the Electric Reliability Council of 

Texas (ERCOT)

Challenge: The Electric Reliability Council of Texas (ERCOT), which manages and operates an energyonly wholesale market covering much of the electricity system in Texas, has experienced several years of

growing demand, increasing VRE (wind) penetration, and consistently tight reserve margins. Some 

stakeholders argue that this tight margin threatens reliability of the system and will not be resolved in an 

energy-only market with price suppression effects of wind power. Other stakeholders argue that tight 

reserve margins signal efficient operation of the market, and that a capacity market would represent a 

shift of risk away from generators to consumers (Anderson 2014). The Public Utility Commission of 

Texas (PUCT) is currently debating whether to establish a dedicated remuneration mechanism to 

encourage greater investment in capacity or to retain the energy-only approach to adequacy.

Proposed Solutions: ERCOT hired the Brattle Group to assess possible options to address this challenge 

through the lens of three key considerations: criteria for investors to invest, effect of proposed rules on 

investment and the market, and possible policy options. Possible actions based on this assessment are 

outlined in the table below (Newell et al. 2012).

15

 

15 The Brattle Group did not propose a specific course of action, noting that the decision would need to be made by policymakers 

and stakeholders, but instead provided an assessment of pros and cons of each possible option. 
24 

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Table 3. Resource Adequacy Mechanism Options Examined for the ERCOT System

Option How 

Reliability 

Level is 

Determined

Who Makes 

Investment 

Decisions

Risk of Low 

Reliability

Investor 

Risks

Economic 

Efficiency

Market 

Design 

Changes

Comments

Energy-only with 

Market-Based 

Reserve Margin 

Market Market High in shortrun; lower in 

long run with 

more DR

High May be 

highest in 

long-run

Easy Depends on substantial 

DR participating to set 

prices at willingness-topay; ERCOT does not yet 

have much DR.

Energy-only with 

Adders to Support 

a Target Reserve 

Margin 

Regulated Market Medium High Lower Easy - Not a reliable way to 

meet target 

- Adders are 

administratively 

determined.

Energy-only with 

Backstop 

Procurement at 

Minimum 

Acceptable 

Reliability

Regulated 

(when 

backstop 

imposed)

Regulated 

(when 

backstop 

imposed)

Low High Lower Easy -Attractive as an 

infrequent last resort, but 

long-term reliance is 

inefficient, non-marketbased, and slippery-slope.

Mandatory 

Resource 

Adequacy 

Requirement for 

Load Serving 

Entities 

Regulated Market Low (with 

sufficient 

deficiency 

penalty)

Med-High Medium (due 

to regulatory 

parameter)

Medium -Well-defined system and 

local requirements and 

resource qualification 

support bilateral trading of 

fungible credits, and 

competition

- Cannot be a forward 

requirement 

- Flexibility: DR is like 

opting out; customers not 

behind a single 

distribution feeder could 

pay for higher reserves 

and reliability.

Resource 

Adequacy 

Requirement with 

Centralized 

Forward Capacity 

Market 

Regulated Market Low Med-High 

(slightly 

less than 

#4)

Medium (due 

to regulatory 

parameters)

Major - Working well in PJM 

- Forward construct can 

efficiently respond to 

retirements and meet 

needs with sufficient lead 

time

- Transparency valuable 

to market participants and 

market monitor 

- Many administrative 

determinations. 

Source: Newell et al. (2012)

Outcome: Based on the Brattle Group assessment and option comparison above, ERCOT is currently 

most closely considering variations of Option 3, an energy-only market where the supplier takes on most 

of the risk, albeit with a mandatory reliability margin. The issue is far from settled, however, as a number 

of contentious regulatory debates on this issue took place in 2013 and 2014. 

The ERCOT snapshot can be contrasted with the UK approach to the question of resource adequacy, in 

which the allocation of cost and risk has also been shifting in recent years.

3.4.1.2 Snapshot: Implementing a Capacity Market in the United Kingdom

Challenge: As noted in the example in Section 2.1.1, the UK government is working to meet ambitious 

RE targets while also ensuring reliability of the electricity system.

Solution: As part of its Energy Market Reform, the UK government also adopted a capacity market

mechanism to ensure security of electricity supply by incentivizing producers to deliver power as needed 
25 

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

under conditions of insufficient capacity (DECC 2013). Ultimately, the capacity market provides an 

additional tariff stream to conventional generators, thus incentivizing resource adequacy investment and 

contributing to long-term system reliability. As noted in Table 2 above, under this mechanism suppliers 

assume most of the risk of resource adequacy, albeit relatively less than under an energy-only paradigm. 

Thus in moving from an energy-only market to a capacity market, some level of risk is shifted to 

customers.

KEY IDEA

Resource adequacy issues raise multiple issues of investment incentives and business model evolution 

for conventional thermal generators, and of risk allocation between generators and load.

In Focus: Resource Adequacy in Contexts of Scarcity and Surplus

In terms of ensuring adequate electricity supply, VRE generation can have different regulatory 

implications depending on the amount of existing generation capacity and pace of new conventional 

capacity additions. From a capacity factor point of view, wind and solar power typically confer between 

15-40% of nameplate capacity. However, the substantive regulatory question pertains more to capacity 

credit, in other words how much the VRE capacity contributes to adequacy and reliability. The answer 

depends on a range of factors, especially patterns of demand in the jurisdiction, and characteristics of the 

generation fleet.

However, the impact of VRE capacity credit in context of scarcity is a more recent area of regulatory

attention. Consider, for example, a hypothetical capacity addition of wind or solar power that would meet 

5% of existing annual demand. In excess capacity settings—where some generators are already operating 

at low capacity usage for economic reasons—such an addition would further contribute to generation 

over-supply, leading to more reductions in capacity usage of conventional generators. All else being 

equal, the same addition in a scarce capacity setting (where demand regularly outstrips supply) would 

mainly contribute to satisfying incremental demand. Thus, in capacity-scarce systems, the same amount 

of VRE generation may pose less of a regulatory concern with regards to ‘asset stranding’ than in an 

excess-capacity power system. A more detailed discussion can be found in (IEA 2014). 

Thus, in excess capacity settings found in most OECD contexts, regulatory attention increasingly focuses 

on the displacement of generation from ‘legacy’ generators and the accelerated removal of those 

generators from the market. Both the financial and system operational impacts of this trend have received 

regulatory attention. Financially, regulatory challenges focus on who should bear the risk of economic 

stranding of power plants. With regards to system operational impacts, the concern is essentially that at 

some point the conventional fleet will no longer be able to provide desired characteristics, especially 

sufficient dispatchability to manage substantial VRE fluctuation events and sufficient system inertia to 

maintain stable and reliable operation during contingency events. In sum, the regulatory questions focus 

on establishing rules and frameworks such that the reduction of the conventional fleet is fair, orderly, and 

maintains reliability. These questions are the focus of much debate in EU settings today, as reflected in 

recent discussions of capacity markets in ACER (2013) and European Commission (2013). 

Regulatory concerns in capacity-scarce systems are typically different. When integrated appropriately 

(i.e., when curtailment is minimized and system operators can manage the variability), new VRE 

generation satisfies latent demand and adds “more tools to the toolbox” for resolving chronic supply 

shortages. In a context of falling VRE costs, capacity-scarce systems are no longer limited to deploying 

coal, gas, hydro, and nuclear plants to meet growing energy demand. Wind and solar PV technologies 

have a unique and sometimes favorable investment profile relative to other options given their 

modularity, flexible sizing, and relatively straightforward project development cycles. In addition, a 

variety of novel forms of financing are available for VRE, ranging from carbon financing to third-party 

solar leasing. 
26 

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There are also, however, examples of capacity-scarce regions in which VRE generation results in 

significantly reduced capacity usage of conventional fleets. Such examples typically arise when VRE 

production is highly seasonal and transmission constraints limit evacuation of VRE power to demand 

centers. For example, in the state of Tamil Nadu in southern India, nearly all of the annual wind 

generation happens during the monsoon season, during which time wind supplies 30-35% of total 

electricity (India Central Electricity Authority 2013) while during the rest of the year it supplies closer to 

5% (see Figure 8). Sharp seasonality of wind generation changes the production profiles and the cash 

flow patterns of conventional generators. The issue also implicates national transmission planning 

processes since additions to transmission capacity could represent an opportunity to evacuate VRE power 

to northern India, thus relieving some of the pressure on conventional generator capacity usage.

In sum, during the early stages, neither flexibility nor capacity concerns are typically dominant for 

regulators. At intermediate and advanced stages, flexibility and capacity rise in importance, albeit in 

different ways depending on the level of capacity scarcity or excess. VRE additions to capacity-scarce

power systems will typically raise flexibility concerns prior to raising adequacy concerns. In contrast, in 

excess capacity power systems, VRE additions typically raise concerns about asset stranding prior to 

raising major flexibility concerns. 

Figure 8. Wind energy as a percentage of energy consumption, Tamil Nadu, 

India, 2010–2013 

Source: India Central Electricity Authority (2013)
27 

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

4 Advanced Stage Regulatory Issues

Advanced stages of VRE penetration incur more complex changes in power system regulation. As of 

2014, few jurisdictions have annual VRE penetrations greater than 20% of total annual generation, so 

empirical evidence of regulatory approaches is relatively scarce.

16 However, Germany, Italy, Spain, and 

Ireland are approaching 20% penetration and will likely surpass it in 2014 (EIA 2013; WEO 2013). This 

section attempts to provide a brief overview of regulatory issues arising at these advanced stages.17

4.1 Advanced Stage VRE Procurement Issues

At advanced stages, the challenges of VRE procurement will likely be similar to those enumerated in 

Section 3.1, but more acute. This section briefly explores the limited empirical evidence of challenges at 

the advanced stage.

4.1.1 Evolution of RE Siting

As VRE penetration grows, siting of VRE generation plants may increasingly be constrained by land-use 

competition (Mai, Sandor, Wiser, et al. 2012) or public opposition (IEA WIND 2013a). Tailoring VRE 

planning and procurement processes to minimize these issues will be an important regulatory concern at 

significant levels of penetration. As a small country with aggressive policy targets, the case of Denmark 

provides insights into this issue.

4.1.1.1 Snapshot: Integrated Offshore Resource Planning in Denmark 

Challenge: A problem of increasingly limited onshore wind sites has driven Denmark to pursue offshore 

wind, which has less favorable costs, but improves resource quality and mitigates many land use and 

public opposition challenges. In the context of aggressive policy goals, Denmark decision makers face the 

challenge of cultivating a robust yet cost-efficient offshore wind development industry. 

Solution: Denmark has refined its approach to offshore wind tenders over the last 10 years (with 8 

offshore wind facilities currently operating) and also gained experience from similar approaches in the oil 

and gas sector. The tender process in Denmark involves the following steps and practices: 

• Site assessment and selection. In order to reduce risk and cost to investors, the government of 

Denmark funds site assessment and selection for suitable offshore wind sites, which is often timeconsuming and expensive for private developers, limiting the pace of investment (Deloitte 2011). 

• Development of tender process. Before releasing initial offshore wind tenders, applicants and the 

Danish Energy Authority (DEA) are given the opportunity to negotiate and address any imprecise or 

unclear aspects of the tender conditions. Tender conditions are then finalized in cooperation with key 

energy authorities in Denmark and, together with licensing requirements, are aligned with Denmark’s 

Electricity Act to ensure an efficient process. DEA also works closely with the system operator, 

Energinet DK, to develop a detailed description of the responsibilities for both the TSO and the tender 

winner in relation to timing for key activities and grid connection conditions. 

• Pre-qualification. Applicants are assessed on the basis of technical and financial qualifications. 

• Tender award. Award of the tender is based on (in order of priority): price/kWh, design and location 

of the project, and timeline for building the project. 

A number of factors contribute to the efficiency of the tender process for offshore wind farms in 

Denmark. First, the government of Denmark takes on much of the upfront burden of site assessment and 

 

16 Only one jurisdiction in the world (Denmark) has VRE penetrations of more than 25% of total annual electricity generation in 

2012. Additionally, Denmark is highly interconnected to both continental Europe and the Nordic system, so the full penetration 

of VRE is not integrated in isolation.

17 Naturally, what today qualifies as ‘advanced stage’ will no longer be ‘advanced’ in 2020 or 2030.
28 

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selection, which greatly reduces cost and thus risk to possible investors. This also allows for an 

accelerated RE investment process. Second, the approach focuses on reducing risk for tender applicants 

by creating a transparent, collaborative, and coordinated process (e.g., integrating licensing requirements, 

etc.). Integration within the DEA of planning, licensing, and permitting responsibility—as well as a 

mandate to play the overall coordination role with other relevant power sector entities—allows for a more 

streamlined and cost-effective process (Jørgensen 2013). 

KEY IDEA

VRE procurement at high penetrations can be sustained through increased support for resource 

characterization and project site assessment, and through streamlined, transparent processes.

4.2 Grid Infrastructure: Advanced Stage Issues

As illustrated in Section 4.1 (as well as in Sections 3.1 and 3.2 above), VRE procurement and grid 

infrastructure typically become increasingly interdependent at intermediate and advanced stages. The 

principles and actions outlined in the preceding sections apply at advanced stages. Corresponding to the 

limited international experience above 20% VRE penetrations, empirical evidence of regulatory best 

practices in grid infrastructure is only now emerging, and is beyond the scope of this report. Subsequent 

CERI research will focus on these issues. 

4.3 Advanced Stage Flexibility

At higher penetrations, VRE exerts noticeable demands on system flexibility. Generally speaking, wind 

and solar have different profiles in this regard: solar dominates variability, and wind dominates 

uncertainty (NREL 2013). In other words, solar output is less uncertain than wind, but is more variable, 

because sunrise and sunset (and to a lesser extent, cloud events) cause variations in power output that are 

larger and faster than those typically observed in wind power systems (see Figure 10). To some extent 

these regular variations can be anticipated and planned for in day-ahead scheduling. Wind power tends to 

change more slowly, but the specific timing of those changes is more uncertain than solar and is more 

difficult to plan for in day-ahead scheduling. 

These differences illustrate how the relative shares of wind and solar capacity in a high-penetration 

scenario will imply different reserve requirements strategies. At a substantive level, this could require 

detailed modeling in order to reach appropriate regulatory determinations of reserve capacity and to 

design appropriate mechanisms for procuring that capacity.

4.3.1 High-penetration Reserve Requirements 

Little empirical evidence exists to guide regulators on procuring sufficient reserves at VRE penetrations 

greater than 20%. Ireland is one of the only relatively isolated systems to manage greater than 15% 

penetration of wind. Other jurisdictions with similar or greater VRE penetrations (e.g., Spain, Portugal, 

Denmark) are more deeply integrated into large balancing areas, thus reducing the need for autonomous 

flexibility. In lieu of empirical evidence, detailed simulations provide the best indications of reserve 

requirements under high VRE penetration scenarios. The U.S. Western Wind and Solar Integration Study, 

Phase 2 (NREL 2013) provides important insights in this regard. 

4.3.1.1 Snapshot: Differential Solar and Wind Reserve Requirements for the Western 

United States 

Challenge: Policymakers in the western United States have noted the need for robust estimation of 

reserve requirements under high wind and solar scenarios. Historically, the majority of research on VRE 

reserve requirements focused primarily on wind, partly due to better data on wind power, and because 

high solar penetrations have historically been less of a concern (WWSIS 2 2013; Orwig et al. 2012; 

Navigant Consulting et al. 2011). Thus, the specific flexibility needs under high solar penetrations was 

less recognized. 
29 

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

Solution: The Western Wind and Solar Integration 

Study (WWSIS) Phase 2 was commissioned to 

investigate system impacts, including reserve 

requirements, under various wind and solar 

penetrations. Reserve impacts are summarized in 

Table 4. Ibanez et al. (2012) proposed a formal 

methodology for calculating solar reserves and this 

methodology was subsequently used in the study 

(WWSIS Phase 2 2013). The WWSIS Phase 2 study 

was one of the first of its depth, and much remains to 

be learned. Results suggest that the magnitude of 

impact on secondary regulation reserves (with a 

response time of seconds to minutes) is roughly 

similar under either wind or solar scenarios, but that 

tertiary, load-following reserves (with a response 

time of minutes to hours) are higher under the 25% 

wind scenario. A primary lesson from this analysis18

is that high wind and high solar scenarios each 

require up to 10% more regulating reserves than a “no renewables” scenario, but that a high wind scenario 

additionally requires load-following reserves of 3% of installed VRE capacity. This is reduced to 1% for 

the high solar scenario.

Table 4. Simulated Reserve Requirements of Different Wind/Solar Mixes in the WWSIS Phase 2 

Analysis (NREL 2013) 

KEY IDEA

At high VRE penetrations, preliminary analysis indicates that additional reserve requirements are 

relatively small compared to total system size, and that there are important differences in reserve impacts

depending on the mix of solar and wind generation. 

4.3.2 Evolution of Demand Response

DR will likely be an important source of flexibility as VRE penetrations grow. The volume, cost, and 

performance characteristics of DR remain important open questions relative to other flexibility options, 

such as interconnection and flexible generation. Preliminary assessments of DR capacity and performance 

characteristics for California shed some light on this issue.

 

18 WWSIS analysis may have limited applicability to other regions around the world given the assumption of five-minute 

economic dispatch and the unique nature of the resource and power system in the western United States.

WWSIS Scenario Contingency (MW) Regulation (MW) Load Following (MW)

No Renewables (0% wind, 0% solar) 3,361 1,120 0

Base Case (9.4% wind, 3.6% solar) 3,361 1,158 1,193

High Wind (25% wind, 8% solar) 3,361 1,236 2,599

High Mix (16.5% wind, 16.5% solar) 3,361 1,211 2,035

High Solar (25% solar, 8% wind) 3,361 1,207 1,545

Figure 9. Five-minute changes in power density: 

load only, high wind, and high solar scenarios 

Source: WWSIS 2 (2013)
30 

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

4.3.2.1 Snapshot: Increasing Flexibility Through the use of Demand-side Resources—

The California Public Utilities Commission (PUC)

Challenge: California’s Renewable Portfolio Standard (RPS) target of 33% renewable installed capacity 

by 2020 requires innovative solutions to address possible integration challenges associated with intrahour variability of VRE. While DR is currently used as an emergency (peak-reduction) resource in 

California, its ability to provide substantial flexibility for VRE integration remains largely untested, 

leaving important knowledge gaps regarding the extent to which it will be part of the flexibility solution.

Proposed Solutions: To address these unknowns, the California Public Utilities Commission (CPUC)

commissioned a study (Perlstein et al. 2012) to assess the capabilities of DR resources and to suggest 

modifications to current DR programs that would allow it to play a substantial role in providing ancillary 

services. Navigant surveyed various DR programs in the state and attempted to quantify the level of fit

between the technical requirements of these programs with existing ancillary services market

requirements. Correcting mismatches between these technical requirements would likely require making

modifications such as: use of telemetry for real-time communications, metering, and control; reduced or 

no advance notification time; automated response to control signals; and increasing number of times and 

frequency with which a program could be dispatched. More details of these suggested adjustments are in 

Table 5.

The CPUC is currently in the process of assessing whether to mandate any modifications to existing DR 

programs or to make other necessary changes. The barriers to change are not insubstantial. For example, 

reducing the response time of DR through automated control equipment requires new capital investment, 

which would in turn require the CPUC to clarify eligibility of various investors to recover such costs. 

Additionally, relaxing the limits on the timing and frequency of DR events could alter the willingness to 

participate in such programs. These issues have yet to be clarified formally in California, but the type of

analysis carried out in this setting to identify specific technical specifications provides important insights 

for regulators. 

Table 5. Necessary Attributes for DR to Supply Ancillary Services in the CAISO Market 

Attributes Needed 

to Provide Ancillary 

Services

Continuous Ramping/ 

Load Following

Spinning and Nonspinning Reserves Regulation Services

Telemetry Required Required Required

Response time Less than one hour, but 

some resources taking 

10 hours or more could 

be used

Less than 10 minutes; 

less than 10 seconds 

to begin ramping is 

desirable 

Less than a minute

Automated response Required Required Required

Event limitations 10 hours or more 

duration, minimum of one 

hour

Dozens to more than 

100 events lasting at 

least one hour each

Continuous availability 

desired

Daily/seasonal 

availability*

24 x 7 year-round, with 

seasonal variation

24 x 7 year-round 24 x 7 year-round

Target end uses Commercial lighting and 

HVAC

Agricultural and 

municipal pumping, 

electric water heat (if 

available)

Temperature controlled 

warehouses, industrial 

motor loads on variable 

frequency drives 

Source: Perlstein et al. (2012)

KEY IDEA

DR represents an important source of flexibility, and large-scale DR participation will depend upon 

regulatory specification of eligibility, performance characteristics, performance validation, and 

compensation mechanisms. 
31 

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

4.4 Resource Adequacy: Advanced Stage Issues

There is limited empirical experience regarding regulatory approaches to ensuring resource adequacy at 

advanced stage penetrations (beyond 20%). Instead, this section focuses on one area that will likely play 

an increasingly important role: institutional coordination across jurisdictional borders.

4.4.1 Institutional Coordination

Institutional coordination—effectively expanding the geographical area over which reserves are shared—

can lead to lower overall system costs through reducing overall uncertainty and variability of VRE 

generation and through increased shared reserve capacity. Merging various balancing areas is one 

example. The creation of organized wholesale markets spanning many balancing areas represents a major 

trend in institutional coordination in the past 30 years. Even in jurisdictions where organized wholesale 

markets have not been established, institutional coordination can assist in VRE integration. Given the 

substantive, procedural, and public interest involved, institutional coordination has significant 

implications for regulators. The case of the U.S. Western Interconnection illustrates this point.

4.4.1.1 Snapshot: Reducing Reserve Requirements in the U.S. Western 

Interconnection Through an Energy Imbalance Market

Challenge: The western United States consists of more than 30 interconnected balancing area authorities 

(BAAs) with abundant wind and solar resources. Anticipating a significant increase in wind and solar 

generation through 2020 and beyond, interest has grown in forms of institutional coordination to 

accommodate increasingly higher penetrations of VRE and reduce VRE integration costs. Policymakers 

and regulators in the various states of the western United States have become increasingly interested in 

substantive and public interest questions about potential region-wide solutions to VRE integration.

Solution: An ‘energy imbalance market’ (EIM) has been proposed to ensure reliable and cost-effective 

VRE integration, as an EIM would allow for intra-hour scheduling of energy and ancillary services 

between balancing areas. An EIM would provide some of the benefits of balancing area expansion 

without requiring the formal merger of balancing areas or the creation of a single market. An EIM 

effectively expands the operational footprint of the power system, reducing aggregate VRE variability and 

allowing for reserve sharing. This generally allows BAA system operators to do more with less: the 

aggregate ramping capability of the generation fleet scales linearly with expansion while the ramping 

needs of the power system scale sub-linearly, resulting in economies of scale (Milligan et al. 2011). In 

early 2012, regulators from the 12 states in the region formed a working group to review proposals and 

commission cost-benefit analyses for various EIM designs. Initial analyses indicated that annual benefits 

(achieved through reserve sharing) outweigh the startup and operating costs by nearly 2-to-1 (Kavulla 

2013). 

But precisely how to implement an EIM across the western United States? This question will require 

significant collaboration between adjacent policymakers and regulators—a process that is at a very early 

stage. A key regulatory consideration is multi-jurisdictional cost estimation and allocation since, even 

though overall system costs are significantly lower, some balancing areas providing additional reserves

may see locational marginal price increases. 

While full regional regulatory coordination has not been achieved, a preliminary EIM is being assembled 

in a more incremental fashion. In November 2013, the California Independent System Operator (CAISO) 

Board of Governors approved a plan to make a filing to FERC to establish an EIM with its adjacent

balancing area to the north, PacifiCorp. In April 2014, NVEnergy, a utility balancing area to the east, filed 

a request with its state regulator to join the CAISO EIM (Electric Light & Power/POWERGRID 

International 2014). 

KEY IDEA

Institutional measures to expand operating footprints results in greater flexibility due to lower aggregate 

variability and higher aggregate reserve capacity, reducing concerns over resource adequacy. 
32 

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

5 Conclusion: Regulation for Comprehensive VRE Integration

This paper charts the progression of regulatory issues across early, intermediate, and advanced stages of 

VRE penetration. The common thread of this progression is increasing interdependency between four key 

domains: facilitating new VRE generation, ensuring adequate grid infrastructure, ensuring short-term 

security of supply (flexibility), and ensuring long-term security of supply (resource adequacy). 

CERI aims to situate VRE deployment and integration into a larger framework. Key to this framework is 

the recognition that all significant changes to a power system incur some need for integration. For 

example, a new transmission line changes power flows and locational prices, and new baseload 

generation changes the economics of all other generators. Especially at high penetrations, VRE 

integration is a complex and iterative issue, involving many interrelated actors and assets, and involving 

various feedback loops.

Regulators around the world are engaging with the key considerations that impact VRE deployment and

integration, especially: 

• Actions that impact the operational practices of the power system

• Actions that impact network development

• Actions that determine the level of reserves required for reliable operation

• Determinations of how to allocate integration costs.

All of these “first order” actions may result in integration costs in the short term (as well as in the 

medium- and long-term). In addition to the above, there are actions that will impact the VRE integration 

challenge through medium- and long-term effects:

• Actions that impact VRE siting

• Actions that impact the terms of VRE interconnection and provision of grid services

• Actions that impact the evolution of the conventional fleet

• Actions that impact the evolution of demand-side responsiveness.

These second order actions have a longer term impact on the cost of VRE integration, as they will direct 

the evolution of the broader power system as VRE penetrations grow. The minimization of these costs is a 

goal of system operators, VRE project developers, customers, and regulators alike. Dialogue and 

exchange between these stakeholder groups—and across the global regulatory community—will be

increasingly important in accelerating the development of systemic approaches to VRE integration. 
33 

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

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